Thermally induced expansion drive in heavy oil reservoirs

ABSTRACT

Aspects of the disclosure involve the production of hydrocarbons from segregated reservoir compartments. Thermal recovery processes within one compartment are used so as to provide thermal energy to a second, adjoining but distinct compartment, increasing fluid pressures within the second compartment to drive hydrocarbons from the second compartment to the first compartment, so that hydrocarbons originating from the second compartment may be produced from the first compartment.

CROSS-REFERENCE TO RELATED APPLICATIONS

Any and all applications for which a foreign or domestic priority claim is identified in the Application Data Sheet as filed with the present application are hereby incorporated by reference under 37 CFR 1.57. This Application claims the benefit of priority to U.S. Provisional Application No. 62/004744, filed May 29, 2014 and Canadian Patent Application No. 2,852,766 filed May 29, 2014.

BACKGROUND

1. Field

This disclosure relates to the field of hydrocarbon reservoir engineering, particularly thermal recovery processes such as steam assisted gravity drainage (SAGD) systems in heavy oil reservoirs.

2. Description of the Related Technology

Some subterranean deposits of viscous hydrocarbons can be extracted in situ by lowering the viscosity of the petroleum to mobilize it so that it can be moved to, and recovered from, a production well. Reservoirs of such deposits may be referred to as reservoirs of heavy hydrocarbon, heavy oil, bitumen, tar sands, or oil sands. The in situ processes for recovering oil from oil sands typically involve the use of multiple wells drilled into the reservoir, and are assisted or aided by thermal recovery techniques, such as injecting a heated fluid, typically steam, into the reservoir from an injection well. One process of this kind is steam-assisted gravity drainage (SAGD).

The SAGD process is in widespread use to recover heavy hydrocarbons from the Lower Cretaceous McMurray Formation, within the Athabasca Oil Sands of northeastern Alberta, Canada. A thick sequence of marine shales and siltstones of the Clearwater Formation unconformably overlies the McMurray Formation in most areas of northeastern Alberta. In some areas, glauconitic sandstones of the Wabiskaw member are present at the base of the Clearwater. The Grand Rapids Formation overlies the Clearwater Formation, and quaternary deposits unconformably overlie the Cretaceous section. The pattern of hydrocarbon deposits within this geological context is complex and varied.

A typical SAGD process is disclosed in Canadian Patent No. 1,130,201 issued on 24 Aug. 1982, in which the functional unit involves two wells that are drilled into the deposit, one for injection of steam and one for production of oil and water. Steam is injected via the injection well to heat the formation. The steam condenses and gives up its latent heat to the formation, heating a layer of viscous hydrocarbons. The viscous hydrocarbons are thereby mobilized, and drain by gravity toward the production well with an aqueous condensate. In this way, the injected steam initially mobilises the in-place hydrocarbon to create a “steam chamber” in the reservoir around and above the horizontal injection well. The term “steam chamber” accordingly refers to the volume of the reservoir which is saturated with injected steam and from which mobilized oil has at least partially drained. Mobilized viscous hydrocarbons are typically recovered continuously through the production well. The conditions of steam injection and of hydrocarbon production may be modulated to control the growth of the steam chamber, to ensure that the production well remains located at the bottom of the steam chamber in an appropriate position to collect mobilized hydrocarbons.

In the ramp-up stage of the SAGD process, after communication has been established between the injection and production wells during start-up, production begins from the production well. Steam is continuously injected into the injection well (usually at constant pressure) while mobilized bitumen and water are continuously removed from the production well (usually at constant temperature). During this period the zone of communication between the wells is expanded axially along the full well pair length and the steam chamber grows vertically up to the top of the reservoir. The reservoir top may be a thick shale (overburden) or some lower permeability facies that cause the steam chamber to stop rising.

Heavy oil recovery techniques such as SAGD create mobile zone chambers in a reservoir, from which at least some of the original oil-in-place has been recovered. However, reservoirs depleted by such processes typically contain a significant volume of residual hydrocarbons, often in reservoir zones that are hydraulically segregated from a mobile production zone, separated from the production zone for example by lower permeability facies such as a shale overburden. There remains a need for methods that may be used to recover these residual hydrocarbons.

In the context of the present application, various terms are used in accordance with what is understood to be the ordinary meaning of those terms. For example, “petroleum” is a naturally occurring mixture consisting predominantly of hydrocarbons in the gaseous, liquid or solid phase. In the context of the present application, the words “petroleum” and “hydrocarbon” are used to refer to mixtures of widely varying composition. The production of petroleum from a reservoir necessarily involves the production of hydrocarbons, but is not limited to hydrocarbon production. Similarly, processes that produce hydrocarbons from a well will generally also produce petroleum fluids that are not hydrocarbons. In accordance with this usage, a process for producing petroleum or hydrocarbons is not necessarily a process that produces exclusively petroleum or hydrocarbons, respectively. “Fluids”, such as petroleum fluids, include both liquids and gases. Natural gas is the portion of petroleum that exists either in the gaseous phase or in solution in crude oil in natural underground reservoirs, which is gaseous at atmospheric conditions of pressure and temperature. Natural gas may include amounts of non-hydrocarbons. The abbreviation POIP stands for “producible oil in place” and in the context of the methods disclosed herein is generally defined as the exploitable or producible oil structurally located above the production well elevation.

It is common practice to segregate petroleum substances of high viscosity and density into two categories, “heavy oil” and “bitumen”. For example, some sources define “heavy oil” as a petroleum that has a mass density of greater than about 900 kg/m³. Bitumen is sometimes described as that portion of petroleum that exists in the semi-solid or solid phase in natural deposits, with a mass density greater than about 1000 kg/m³ and a viscosity greater than 10,000 centipoise (cP; or 10 Pa·s) measured at original temperature in the deposit and atmospheric pressure, on a gas-free basis. Although these terms are in common use, references to heavy oil and bitumen represent categories of convenience, and there is a continuum of properties between heavy oil and bitumen. Accordingly, references to heavy oil and/or bitumen herein include the continuum of such substances, and do not imply the existence of some fixed and universally recognized boundary between the two substances. In particular, the term “heavy oil” includes within its scope all “bitumen” including hydrocarbons that are present in semi-solid or solid form.

A “reservoir” is a subsurface formation containing one or more natural accumulations of moveable petroleum, which are generally confined by relatively impermeable rock. An “oil sand” or “tar sand” reservoir is generally comprised of strata of sand or sandstone containing petroleum. A “zone” in a reservoir is an arbitrarily defined volume of the reservoir, typically characterised by some distinctive property. Zones may exist in a reservoir within or across strata, and may extend into adjoining strata. In some cases, reservoirs containing zones having a preponderance of heavy oil are associated with zones containing a preponderance of natural gas. This “associated gas” is gas that is in pressure communication with the heavy oil within the reservoir, either directly or indirectly, for example through a connecting water zone.

“Thermal recovery” or “thermal stimulation” refers to enhanced oil recovery techniques that involve delivering thermal energy to a petroleum resource, for example to a heavy oil reservoir. There are a significant number of thermal recovery techniques other than SAGD, such as cyclic steam stimulation, in situ combustion, hot water flooding, steam flooding and electrical heating. In general, thermal energy is provided to reduce the viscosity of the petroleum to facilitate production. The addition of heat may also have geophysical effects within the reservoir, for example causing the expansion of reservoir fluids, which may in turn lead to increases in pore pressures. In oil sand reservoirs, thermal expansion of bitumen within a reservoir may for example create pore pressures that are high enough to produce reservoir expansion, in effect moving sand grains apart (R. M. Butler, The expansion of tar sands during thermal recovery, Journal of Canadian Petroleum Technology, 1986, volume 25, issue 5, p. 51-56). The evolution of temperature and heat flow within a reservoir depends upon the thermal properties of the reservoir materials, including volumetric heat capacity, thermal conductivity, thermal diffusivity and the coefficients of thermal expansion.

A “chamber” within a reservoir or formation is a region that is in fluid/pressure communication with a particular well or wells, such as an injection or production well. For example, in a SAGD process, a steam chamber is the region of the reservoir in fluid communication with a steam injection well, which is also the region that is subject to depletion, primarily by gravity drainage, into a production well.

“Reservoir compartmentalization” is a term used to describe the segregation of a petroleum accumulation into a number of distinct fluid/pressure compartments. In general, this segregation takes place when fluid flow is prevented across sealed boundaries in the reservoir. These boundaries may for example be caused by a variety of geological and fluid dynamic factors, involving: static seals that are completely sealed and capable of withholding (trapping) petroleum deposits, or other fluids, over geological time; and dynamic seals that are low to very low permeability flow barriers that significantly reduce fluid cross-flow to rates that are sufficiently slow to cause the segregated chambers to have independent fluid pressure dynamics, although fluids and pressures may equilibrate across a dynamic seal over geological time-scales (Reservoir compartmentalization: an introduction, Jolley et al., Geological Society, London, Special Publications 2010, v. 347, p. 1-8). A reservoir compartment may be hydraulically confined, so that fluids are prevented from moving beyond the compartment by sealed boundaries confining the compartment.

SUMMARY

Some aspects described herein involve the production of hydrocarbons from reservoir compartments that are initially segregated into distinct fluid/pressure compartments, with the compartments in thermal communication. Thermal recovery techniques applied to one compartment are used so as to provide thermal energy to a second, adjoining but distinct fluid/pressure compartment, in which the second compartment is hydraulically confined by sealed boundaries. Production from the first compartment is managed in conjunction with effecting thermal communication from the first compartment to the second compartment. Heating of the second, confined compartment, increases fluid pressures within the second compartment. This increase in fluid pressure in the second compartment, which may be coupled to production of fluids from the first compartment, gives rise to a pressure differential that is used to drive hydrocarbons from the second compartment to the first compartment, so that hydrocarbons originating from the second compartment are produced from the first compartment. The hydrocarbons may for example be a heavy oil that is originally immobile in the second compartment, which is mobilized by the thermal energy communicated from the first compartment, and driven by the pressure differential to the first compartment for production.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic illustration of a typical SAGD well pattern, showing paired injector and producer well pairs, each have a heel and a toe within the hydrocarbon rich pay zone of the formation.

FIG. 2 is schematic illustration of cretaceous stratigraphy of the Athabasca oil sands.

FIG. 3 is a schematic illustration of a compartmentalized heavy oil reservoir.

FIG. 4 is a cross sectional view of an exemplary completion for an injector well.

FIG. 5 is a cross sectional view of an exemplary completion for a production well, in a start-up configuration for circulation, illustrating an embodiment employing gas lift.

FIG. 6 is a cross sectional view of an exemplary completion for a production well, illustrating an embodiment employing an electric submersible pump (ESP) for production operations following start up. Typically, after circulation start-up, the 2″ coiled tubing string will be removed and the well equipped with a high temperature ESP capable of pumping fluid from the well into production gathering facilities.

FIG. 7 is a cross sectional view of an embodiment of completion for a production well.

DETAILED DESCRIPTION

Various aspects described herein may involve the drilling of SAGD well pairs within a reservoir 11, as illustrated in FIG. 1, with each injector well 13, 19, 23, paired with a corresponding producer well 15, 17 and 21. Each well has a completion 14, 12, 16, 18, 20 and 22 on surface 10, with a generally vertical segment leading to the heel of the well, which then extends along a generally horizontal segment to the toe of the well. In very general terms, to provide a general illustration of scale in selected embodiments, these well pairs may for example be drilled in keeping with the following parameters. There may be approximately 5 m depth separation between the injection well and production well. The SAGD well pair may for example average approximately 800 m in length. The lower production well profile may generally be targeted so that it is approximately 1 to 2 m above the SAGD base. The development of steam chambers around each well pair may be illustrated in cross sectional views along axis 24, which is perpendicular to the longitudinal axial dimension of the horizontal segments of the well pairs.

As illustrated in FIG. 2, the stratigraphy of the Athabasca oil sands varies geographically, and in places includes oil sand deposits that are separated by distinct barrier layers, such as marine shales. FIG. 3 is a cross sectional view along axis 24 of FIG. 1, illustrating a hydrocarbon reservoir in which a primary heavy oil compartment 30 is hydraulically separated from a secondary heavy oil compartment 40 by a permeability barrier 32, so that under initial reservoir conditions heavy oil does not flow across the permeability barrier. The secondary heavy oil compartment 40 is hydraulically confined, for example by shale cap rock 42.

In the embodiment illustrated in FIG. 3, a SAGD thermal recovery technique is applied to the primary heavy oil compartment 30, forming steam chamber 28 around injection well 19, to mobilize heavy oil for production through production well 17. Thermal energy applied to the primary heavy oil compartment 30 by way of steam chamber 28 is communicated across permeability barrier 32 to secondary heavy oil compartment 40 to heat heavy oil in the secondary heavy oil compartment 40. In some embodiments, other thermal recovery techniques can be used, including cyclic steam stimulation (CSS), electrical or electromagnetic heating, hybrid solvent-steam processes and in-situ combustion. This is carried out so as to increase fluid pressure within the secondary heavy oil compartment 40 by way of thermal expansion of the confined fluids in secondary compartment 40.

By adjusting the production and/or injection of fluids in primary heavy oil compartment 30 or by adjusting the thermal energy delivered to the reservoir via an electric or electromagnetic heating source, as well as the delivery of thermal energy to secondary heavy oil compartment 40, conditions may be arranged so that the fluid pressure in the secondary heavy oil compartment 40 rises above the fluid pressure in the primary heavy oil compartment 30, to create a fluid pressure differential between the compartments. Under these circumstances, a fluid flow path may be provided across the permeability barrier, for example by a well completed so as to drain mobilized heavy oil from secondary heavy oil compartment 40 to primary heavy oil compartment 30, driven by the fluid pressure differential between the compartments. In this way, fluids may be recovered from primary heavy oil compartment 30 that include heavy oil from secondary heavy oil compartment 40, for example by way of SAGD production well 17.

In some embodiments, the relative positions of primary and secondary heavy oil compartments may be varied. For example, the primary compartment may be above or below the secondary compartment, with an intervening permeability barrier that is substantially horizontal. In some embodiments, the compartments may be spaced apart horizontally, with a substantially vertical permeability barrier. In practice, the adjoining compartments will typically have a complex geometric relationship, with vertical and horizontal components of offset.

The hydraulic confinement of the secondary compartment may be by way of a static seal formed by a geological pattern of surrounding permeability barriers. In some embodiments, hydraulic confinement may be caused or enhanced by the imposition of dynamic fluid flow barriers that are not naturally present, such as synthetic permeability barriers formed by pressurization of a hydraulically adjoining overlying gas zone, or underlying or overlying water zones, or laterally adjacent gas or water zones. In some embodiments, immobile bitumen may form part of a permeability barrier around the secondary compartment, zones of fluid injection may form a production seal or natural static or dynamic seals may form the production seal.

Once a fluid flow path is provided for fluids to exit the secondary compartment, the drive mechanism for that flow may consist principally of expansion of pressurized liquids from the secondary compartment as it travels towards the pressure sink afforded by the lower pressure primary compartment. In some embodiments, the drive mechanism may involve a solution gas drive due to expansion of gases, or may involve combinations of these mechanisms. The basic drive mechanism provided by fluid expansion within the confined compartment may also be enhanced by the addition of other drive mechanisms, such as cyclic steam stimulation, hot water flood, or steam flood, combinations thereof or in-situ combustion, hybrid steam-solvent processes, electric and electromagnetic heating.

The fluid flow path for hydrocarbons from the secondary compartment to the primary compartment may for example be by way of a conduit, such as a well, introduced to guide the flow of mobilized hydrocarbons. In the event that formation geology in the secondary compartment is characterized by poor effective vertical permeability (e.g., clasts, shale lenses, IHS), vertical or inclined wells may for example be employed to drain fluids horizontally (i.e., in the preferred direction of flow) from the secondary compartment into the wellbore that provides a fluid flow path across the permeability barrier to the primary compartment.

In some embodiments, temperature and/or pressure can be controlled such as to induce stresses that can create a high degree of deformation of the rock that comprises the permeability barrier and eventually can yield a failure of the permeability barrier creating a fluid flow path for hydrocarbons from the secondary compartment to the primary compartment.

In selected embodiments, permeability barriers are generally comprised of shale. Failure of the permeability barrier can happen because the changes in stresses caused by the pressure and the temperature change in the reservoir compartments. It can also happen because of the existence of thermal pore pressure inside the shale, which is caused by the heating up of the water inside the shale. Water expands more than the shale matrix upon heating and it cannot flow out because of the low permeability shale—creating high pore pressure inside the shale.

In select embodiments, thermal energy can also be imparted to the permeability barrier from an adjacent well using a variety of methods such as directing a high temperature fluid directly to the permeability barrier until the temperature of the barrier increases sufficiently to induce fracturing of the shale layer.

In some embodiments, injection of a fluid from an injection well to create a localized pressure increase in the permeability barrier sufficiently high as to create a hydraulic fracturing of the permeability barrier.

Some aspects of the disclosure involve completing wells in various configurations. Exemplary completions for injector, producer on gas lift, producer on electric submersible pump (ESP) and simulated producer are shown in FIGS. 4, 5, 6 and 7 respectively. In some embodiments, a slotted liner may be used, for example, as depicted in FIG. 4. The slotted liner may be similar to that disclosed in Canadian Patent Application 2,616,483, published Jun. 29, 2008.

Detailed computational simulations of reservoir behavior may be carried out. The thermal properties of the reservoir may for example be characterized using two rock types. Rock type one may for example represent clean sand of the McMurray formation in Alberta, Canada. A second rock type representing a relatively impermeable stratum or strata, such as shale, may be used to simulate a permeability barrier. Exemplary properties of the two such rock types may for example be defined with the following properties:

Rocktype 1 (Sand)

Porosity Reference Pressure=100 kPa

Compressibility=1e−6 1/kPa

Volumetric Heat Capacity 2.39e6 J/(m³*C)

Rock Thermal Conductivity=196,820 J/(m*day*C)

Water Thermal Conductivity=552,960 J/(m*day*C)

Oil Thermal Conductivity=0

Gas Thermal Conductivity=0

Rocktype 2 (Shale Overburden & Underburden)

Porosity Reference Pressure=100 kPa

Compressibility=1e6 1/kPa

Volumetric Heat Capacity 2.39e6 J/(m³*C)

Rock Thermal Conductivity=146,880 J/(m*day*C)

Water Thermal Conductivity=0

Oil Thermal Conductivity=0

Gas Thermal Conductivity=0

In an exemplary embodiment of the process described herein, carried out in the McMurray and Wabiskaw formations, typical values of the relevant formation thicknesses are as follows: McMurray Formation in which SAGD is being conducted 38 m; impermeable mudstone immediately overlying the McMurray 6 m; affected Wabiskaw zone immediately overlying the mudstone 7 m. In this embodiment, the ascent within the McMurray Formation of the SAGD steam chamber was confirmed with temperature profiles. It was also confirmed with 4D (Time Lapse) Seismic data. Progressive heating of the overlying Wabiskaw was clearly evident in the 4D seismic data, over time: year 1—No seismic anomalies evident in Wabiskaw; year 2—anomalies appear, indicating some heating of Wabiskaw; year 3—anomalies signal continued heating of Wabiskaw.

Because of the Wabiskaw zone's geological confinement, the pressure within the Wabiskaw compartment increased markedly as it was heated conductively from below. This thermally induced over-pressuring of the Wabiskaw was first identified in year 3, while attempting to drill a steam chamber core. Whereas the normal formation pressure at this depth and in this area is approximately 2000 kPa, the pressure measured via drill stem test was approximately 6500 kPa. To utilize this pressure increase, a production well was drilled into the Wabiskaw, producing significant quantities of oil on a sustained basis, gradually reducing the reservoir pressure in the Wabiskaw.

These results indicate that conductive heating of bitumen in the confined Wabiskaw zone, with heat arriving from the underlying SAGD steam chamber in the McMurray formation, induced an increase in reservoir pressure within the Wabiskaw from ˜2000 kPa to ˜6500 kPa. Field data confirm that the mudstone separating the underlying McMurray Formation from the overlying Wabiskaw zone is competent, allowing no hydraulic communication between the two zones. If the two zones were hydraulically communicating, the pressure in the Wabiskaw would equilibrate at a value closer to that of the McMurray Formation (e.g., ˜2000 kPa). Instead, the Wabiskaw reached a pressure of ˜6500 kPa, illustrating that high pressure may be induced by conductive heating of the Wabiskaw due to its geological confinement.

Although various embodiments of the invention are disclosed herein, many adaptations and modifications may be made within the scope of the invention in accordance with the common general knowledge of those skilled in this art. For example, any one or more of the injection, production or vent wells may be adapted from well segments that have served or serve a different purpose, so that the well segment may be re-purposed to carry out aspects of the invention, including for example the use of multilateral wells as injection, production and/or vent wells. Such modifications include the substitution of known equivalents for any aspect of the invention in order to achieve the same result in substantially the same way. Numeric ranges are inclusive of the numbers defining the range. The word “comprising” is used herein as an open-ended term, substantially equivalent to the phrase “including, but not limited to”, and the word “comprises” has a corresponding meaning. As used herein, the singular forms “a”, “an” and “the” include plural referents unless the context clearly dictates otherwise. Thus, for example, reference to “a thing” includes more than one such thing. Citation of references herein is not an admission that such references are prior art to the present invention. Any priority document(s) and all publications, including but not limited to patents and patent applications, cited in this specification are incorporated herein by reference as if each individual publication were specifically and individually indicated to be incorporated by reference herein and as though fully set forth herein. The invention includes all embodiments and variations substantially as hereinbefore described and with reference to the examples and drawings. 

What is claimed is:
 1. A process for mobilizing fluids in a subterranean formation, the process comprising: a) selecting a hydrocarbon reservoir in the formation bearing heavy oil, the reservoir having a primary heavy oil compartment hydraulically separated from a secondary heavy oil compartment by a permeability barrier, wherein under initial reservoir conditions heavy oil does not flow across the permeability barrier, and wherein the secondary heavy oil compartment is hydraulically confined; b) applying a thermal recovery technique to the primary heavy oil compartment to mobilize heavy oil therein, so that thermal energy applied to the primary heavy oil compartment is communicated across the permeability barrier to the secondary heavy oil compartment to heat heavy oil in the secondary heavy oil compartment so as to increase fluid pressure within the secondary heavy oil compartment; c) adjusting the production and/or injection of fluids in the primary heavy oil compartment and the delivery of thermal energy to the secondary heavy oil compartment, so that the fluid pressure in the secondary heavy oil compartment rises above the fluid pressure in the primary heavy oil compartment to create a fluid pressure differential between the compartments; d) providing a fluid flow path across the permeability barrier so that mobilized heavy oil flows from the secondary heavy oil compartment to the primary heavy oil compartment, driven by the fluid pressure differential between the compartments.
 2. The method of claim 1, further comprising recovering a produced fluid from the primary heavy oil compartment, wherein the produced fluid comprises heavy oil from the secondary heavy oil compartment.
 3. The method of claim 2, wherein the production and injection of fluids in the primary heavy oil compartment and the delivery of thermal energy to the secondary heavy oil compartment is carried out by a steam assisted gravity drainage process in the primary heavy oil compartment, comprising a SAGD injection well and a SAGD production well placed in the primary heavy oil compartment.
 4. The method of claim 3, wherein the produced fluid from the primary heavy oil compartment is recovered through the SAGD production well.
 5. The method of claims 1, wherein the primary heavy oil compartment is generally below the secondary heavy oil compartment.
 6. The method of claim 1, wherein the secondary heavy oil compartment is hydraulically confined by a static seal formed by a geological pattern of surrounding permeability barriers.
 7. The method of claim 1, wherein the secondary heavy oil compartment is hydraulically confined at least in part by the imposition of a dynamic fluid flow barrier.
 8. The method of claim 1, wherein an additional drive mechanism is applied to the secondary heavy oil compartment to enhance fluid flow from the secondary compartment to the primary compartment.
 9. The method of claim 8, wherein the additional drive mechanism is one or more of: cyclic steam stimulation, hot water flood, or steam flood.
 10. The method of claim 1, wherein the fluid flow path across the permeability barrier is a well having a horizontal trajectory component and a vertical trajectory component. 